Loss of well completion fluids to the formation can cause formation damage, i.e., a reduction in permeability and conductivity near the wellbore, and thereby reduce the production of hydrocarbons. For example, fluid leakoff into the formation can occur during gravel placement and/or screen installation due to overbalance pressure, i.e., the difference in hydraulic head and reservoir pressure. After perforating, as another example, the completion fluid also tends to leak into the formation. The completion fluid can also be lost during the trip out and trip in to assemble the production tubing and the screen after the well is gravel packed. Generally, a flapper valve is used to isolate the screen and the formation from the wellbore fluids after the service tool and wash pipe are pulled out of the screen. If the flapper valve fails to isolate, the brine can be lost to the formation.
Completion fluids are often made of, for example, a high density brine. As used herein, a high density brine, sometimes also called a heavy brine or high brine, refers to an aqueous inorganic salt solution having a specific gravity of greater than about 1.02 kg/L (8.5 lb/gal (ppg)), 1.08 kg/L (9 ppg) or 1.14 kg/L (9.5 ppg), especially above 1.2, 1.32, 1.44 or 1.5 kg/L (10, 11, 12 or 12.5 ppg), or up to 1.8 kg/L (15 ppg). The loss of high density brine is undesirable not only because of the cost of the brine, but also because of the damage it can cause to the formation permeability. For example, calcium and zinc bromides, which are used in some high density brines, can form stable, acid insoluble compounds when contacted with brines occurring in the formation. In addition, unloading these dense brines from the formation is not an easy task. See SPE 29525 (1995).
To control the fluid leak-off to the formation a fluid loss control pill has been used to block the perforations or to form a filtercake on the formation face. In the case of fluid loss through the screen during trip out for assembling the screen and the production tubular, the fluid loss pill is spotted inside the screen to block the openings in the screen. Typically, crosslinked hydroxyethyl cellulose (HEC) with sized calcium carbonate, rock salt or oil soluble resins is used as a loss control pill. See SPE 19752 (1989); SPE 30119 (1995); SPE 36676 (1996); SPE 39438 (1998); SPE 53924 (1999); SPE 58734 (2000); SPE 73771 (2002); and SPE 93319 (2005). A high concentration of the polymer, e.g., 9.6-14.4 g/L (80-120 pounds per thousand gallons (ppt)), is used to reduce leak-off to high permeability formations and also to contain the depth of invasion of polymer into the formation. A typical completion process using crosslinked HEC with salt solids is described in SPE 30119.
To initiate production following placement of the HEC/particulate fluid loss control pill, the filtercake of crosslinked HEC and the particulates must be removed from the perforations, the formation face, the screen, and so forth. Thus, acid and breakers are circulated prior to gravel packing, to break the polymer and dissolve the solids used in the pill. However, the cleanup is not uniform in these treatments due to several reasons including channeling of the treatment fluid into the first few perforations, incomplete removal of bridging agents, blockage of screen openings with bridging agent, insufficient cleanup of polymer from the filtercake and the formation, reduction in gravel pack permeability due to trapped debris from the fluid loss pill, and so on. See SPE 30119.
The cleanup difficulties are especially severe when the filtercake is sandwiched between the formation face and the gravel pack, e.g., when the HEC/particulate is applied in advance of gravel packing. The polymer tends to hold the calcium carbonate particles together and it is extremely difficult to initiate flow back from the formation to lift off the filtercake into the gravel pack. For this reason, calcium carbonate/polymer systems are used primarily to bridge against screens, and the size distribution of commercially available calcium carbonate particles has been carefully selected to successfully bridge with minimal particle invasion.
In addition, mixing the fluid loss control and clean up pills at the wellsite can require on-site quality control and expertise. For example, the HEC must be crosslinked prior to placement at the formation since crosslinking within the formation may lead to additional damage from polymer that cannot be easily broken.
In the stimulation of formations generally by hydraulic fracturing, it is also known to use a fluid loss additive (FLA) in carrier fluids with viscosifiers such as polymers to inhibit excessive fluid loss from the carrier fluid into the fracture face, for example. The FLA helps form a filtercake on the surface of the fracture, reducing permeability at the fluid-rock interface and improving fracturing efficiency. Conventional FLA usually consists of fine particles, such as mica or silica flour with a broad distribution of particle sizes designed to effectively plug the pore throats of the rock matrix. Starches or other polymers can be added to help fill in the spaces and further reduce the flow.
U.S. Pat. No. 3,960,736 discusses the use of esters to offer a delayed acid which will break a fracturing fluid used to carry proppant into a hydraulic fracture by attacking the polymer and borate crosslinks. Similarly, acid generation mechanisms are employed in U.S. Pat. No. 4,387,769 and U.S. Pat. No. 4,526,695.
The use of a hydrolysable polyester material as an FLA for fluid loss control in fracturing systems has also previously been proposed; further, degradation products of such materials have been shown to cause delayed breaking of fracturing fluids. U.S. Pat. No. 4,715,967 discloses the use of polyglycolic acid (PGA) as a fluid loss additive to temporarily reduce the permeability of a formation. SPE 18211 discloses the use of PGA as a fluid loss additive and gel breaker for crosslinked hydroxypropyl guar fluids. U.S. Pat. No. 6,509,301 describes the use of acid forming compounds such as PGA as delayed breakers of surfactant-based vesicle fluids, such as those formed from the zwitterionic material lecithin.
Encapsulated breakers based on oxidants and/or enzymes are also well known in fracturing systems. Typically, in the prior art the encapsulated breakers are injected with the proppant in the carrier fluid. The breaker capsules are generally the same size as the proppant particles, to facilitate distribution in the proppant pack and promote breakage when the fracture is closed to release the breaker to react with the viscosifier and reduce the viscosity of the carrier fluid to restore permeability to the proppant pack.
Other references that may be pertinent to the present invention include U.S. Pat. No. 6,394,185; U.S. Pat. No. 6,342,467; U.S. Pat. No. 5,333,689; SPE 58734; SPE 36676; SPE 19752; SPE 93319; SPE 53924; SPE 29525; SPE 73771; SPE 39438; and SPE 30119.
To the extent they are not inconsistent with present disclosure, each of the references mentioned herein are hereby incorporated herein by reference in their entirety for the purpose of US patent practice and other jurisdictions where permitted.